Carbon dioxide energy storage and enhanced oil recovery

ABSTRACT

The present invention is a method and apparatus for the subsurface storage of carbon dioxide in reservoir formations, to provide energy storage for electrical load balancing, and to enable the enhanced recovery of hydrocarbon fluids from the subsurface formations by gravity drainage. Multiple propped vertical inclusions are propagated into hydrocarbon fluid bearing reservoir formations at various vertical depths from well casings. Carbon dioxide is injected and stored in the formations. At off-peak power demand periods, carbon dioxide is pumped by a pump/turbine from the low energy formation into a deeper high energy formation, and at peak power demand periods the carbon dioxide is released from the high energy formation and flows to the low energy formation, driving the pump/turbine to generate electricity. Hydrocarbon fluids are produced from the formations depending on the formation conditions. Additional carbon dioxide is injected into the system as hydrocarbon fluids are extracted.

CLAIM OF PRIORITY

This application claims priority from U.S. Provisional Patent Application No. 61/900,612 filed on Nov. 6, 2013, which is relied upon and incorporated herein in its entirety by reference.

TECHNICAL FIELD

The present invention generally relates to the geological storage of carbon dioxide, the closed cycling of carbon dioxide from one reservoir formation to another for energy storage to balance electrical loads, and the subsequent enhanced recovery of petroleum fluids (oil) from the subsurface formation by gravity drainage.

BACKGROUND OF THE INVENTION

Carbon capture and storage in geological formations is a much focused research area due to the greenhouse gas effects of releasing carbon dioxide to the atmosphere. The carbon dioxide can be stored in geological formations in the form of a trap, the trap being a depleted oil and gas field or a saline aquifer. The cost of such storage is high, but in the case of natural gas reservoirs containing high levels of carbon dioxide, such storage may be easily justified by the value of the natural gas extracted. In the case of carbon capture from coal fire power plants, the cost of such carbon dioxide storage could be excessive for the operation of the power plant. A need therefore exists for a cheaper storage scheme for the geological storage of carbon dioxide.

Energy storage schemes for balancing peak and off-peak electrical demand are now in even greater demand due to the fact that most renewable energy sources, such as wind, tidal and solar provide only intermittent power. Geological energy storage schemes may assist in balancing electrical loads on a power grid consisting of pumped hydroelectric and compressed air energy storage schemes. The pumped hydroelectric scheme requires surface reservoir storage and either topographical relief to provide the differential head between the two stored reservoir states or the injection of the fluid into the subsurface into either an aquifer or constructed subsurface caverns. Water is pumped by a pump/turbine to a higher elevation during off-peak demand, and during peak demand the water flows from the higher elevation reservoir to the lower reservoir, and drives the pump/turbine to generate electricity. Using a variable speed generator the electrical loads can be even better balanced.

The compressed air energy storage scheme involves compressing air and injecting it into either a subsurface aquifer or underground constructed caverns. The caverns are solution mined in salt formations or excavated in hard rock formations. Air is compressed and injected into the subsurface during off-peak demand and at peak demand air is released from storage to the atmosphere and drives the pump/turbine for electrical generation.

In both schemes the cost of the demand electricity is high, so there is a need for a cheaper geological energy storage system for balancing electrical loads.

Most hydrocarbon fluids (oil) are produced by primary, secondary, and tertiary recovery methods. In many cases, the recovery of the hydrocarbon fluids is only a small percentage of the original oil in place. The reasons for the low recovery can be attributed to many factors. Gravity drainage of hydrocarbon fluids as a recovery mechanism is well known to yield very high recovery factors. Gravity drainage, however, is not applicable to many reservoirs due to the reservoir's low vertical permeability and the low mobility of the oil. Thus, a need exists for a method to enhance the gravity drainage of such reservoirs and thus enable the recovery of significant quantities of stranded hydrocarbon fluids. Carbon dioxide at supercritical state and above the miscible pressure of the hydrocarbons provides a number of mechanisms to assist oil recovery, such as lower gas-oil capillary pressure and hence more effective gravity drainage, higher oil relative permeability, vaporizing of intermediate components, swelling of the oil, oil viscosity reduction, and solution gas drive.

Gravity drainage can yield oil recoveries greater than 80% in clean high permeable reservoirs. Reservoirs with moderate to low vertical permeability are not suitable for gravity drainage because the recovery mechanism is extremely slow in these types of formations. If multiple vertical high permeable propped planar inclusions are installed in such reservoirs, then oil recovery is virtually independent of the reservoir vertical permeability, Hocking et al., “Unimpaired Performance of Single-Well SAGD in Variable Geology,” Gas & Oil Expo & Conference North America, 2011, and thus is a viable oil recovery method. Such vertical propped planar inclusions combined with the availability of large quantities of carbon dioxide for enhanced recovery, makes many reservoirs that are considered depleted as candidates for significant enhanced oil recovery of these stranded hydrocarbon fluid reserves.

Techniques used in hard, brittle rock to form fractures therein are typically not applicable to ductile formations comprising unconsolidated, weakly cemented sediments. The method of controlling the azimuth of a vertical hydraulic planar inclusion in formations of unconsolidated or weakly cemented soils and sediments by slotting the well casing or installing a pre-slotted or weakened well casing at a predetermined azimuth has been previously disclosed. A vertical hydraulic planar inclusion can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic planar inclusions at differing azimuths from a single well casing can be initiated and propagated for the enhancement of petroleum fluid production from the formation. See U.S. Pat. No. 6,216,783 to Hocking et al., U.S. Pat. No. 6,443,227 to Hocking et al., U.S. Pat. No. 6,991,037 to Hocking, U.S. Pat. No. 7,404,441 to Hocking, U.S. Pat. No. 7,640,975 to Cavender et al., U.S. Pat. No. 7,640,982 to Schultz et al., U.S. Pat. No. 7,748,458 to Hocking, U.S. Pat. No. 7,814,978 to Steele et al., U.S. Pat. No. 7,832,477 to Cavender et al., U.S. Pat. No. 7,866,395 to Hocking, U.S. Pat. No. 7,950,456 to Cavender et al., U.S. Pat. No. 8,151,874 to Schultz et al. A vertical hydraulic planar inclusion can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic planar inclusions at differing azimuths from a single well casing can be initiated and propagated for the enhancement of petroleum fluid production from the formation. Unconsolidated or weakly cemented sediments behave substantially different from brittle rocks from which most of the hydraulic fracturing experience is founded.

The methods disclosed above find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which obtaining directional or geometric control over inclusions as they are being formed is typically very difficult. Weakly cemented sediments are primarily frictional materials because they have minimal cohesive strength. An uncemented sand, having no inherent cohesive strength (i.e., no cement bonding holding the sand grains together), cannot contain a stable crack within its structure and cannot undergo brittle fracture. Such materials are categorized as frictional materials which fail under shear stress, whereas brittle cohesive materials, such as strong rocks, fail under normal stress.

The term “cohesion” is used in the art to describe the strength of a material at zero effective mean stress. Weakly cemented materials may appear to have some apparent cohesion due to suction or negative pore pressures created by capillary attraction in fine grained sediment, with the sediment being only partially saturated. These suction pressures hold the grains together at low effective stresses and, thus, are often called apparent cohesion.

The suction pressures are not true bonding of the sediment's grains, because the suction pressures would dissipate due to complete saturation of the sediment. Apparent cohesion is generally such a small component of strength that it cannot be effectively measured for strong rocks, and only becomes apparent when testing very weakly cemented sediments.

Geological strong materials, such as relatively strong rock, behave as brittle materials at normal petroleum reservoir depths, but at great depth (i.e. at very high confining stress) or at highly elevated temperatures, these rocks can behave like ductile frictional materials. Unconsolidated sands and weakly cemented formations behave as ductile frictional materials from shallow to deep depths, and the behavior of such materials are fundamentally different from rocks that exhibit brittle fracture behavior. Ductile frictional materials fail under shear stress and consume energy due to frictional sliding, rotation, and displacement.

Conventional hydraulic dilation of weakly cemented sediments is conducted extensively on petroleum reservoir formations as a means of sand control. The procedure is commonly referred to as “Frac-and-Pack.” In a typical operation, the casing is perforated over the formation interval intended to be fractured, and the formation is injected with an injection fluid of low gel loading without proppant, in order to form the desired two winged structure of a fracture. Then, the proppant loading in the injection fluid is increased substantially to yield tip screen-out of the fracture. In this manner, the fracture tip does not extend further, and the fracture and perforations are backfilled with proppant.

The process, producing a two winged fracture, is formed as in conventional brittle hydraulic fracturing. Such a process, however, has not been duplicated in the laboratory or in shallow field trials. In laboratory experiments and shallow field trials chaotic geometries of the injection fluid has been observed, with many cases evidencing cavity expansion growth of the injection fluid around the well and with deformation or compaction of the host formation.

Weakly cemented sediments behave like a ductile frictional material in yield due to the predominantly frictional behavior and the low cohesion between the grains of the sediment. Such materials do not “fracture” and, therefore, there is no inherent fracturing process in these materials as compared to conventional hydraulic fracturing of strong brittle rocks.

Linear elastic fracture mechanics is not generally applicable to the behavior of weakly cemented sediments. The knowledge base of propagating viscous planar inclusions in weakly cemented sediments is primarily from recent experience over the past ten years, and much is still not known regarding the process of viscous fluid propagation in these sediments.

Accordingly, there is a need for a method and apparatus for construction of vertical multiple azimuth vertical propped planar inclusions to assist in the more efficient injection and withdrawal of petroleum fluids from the subsurface, for the geological storage of carbon dioxide, a subsurface energy storage scheme for balancing electrical loads, and a more efficient and effective recovery method of hydrocarbon fluids from the subsurface formations.

SUMMARY OF THE INVENTION

The present invention is a method and apparatus for subsurface storage of carbon dioxide, for providing energy storage for electrical load balancing, and for enabling more efficient, more economical, and less environmental impact for the enhanced recovery of petroleum fluids from the subsurface formation by gravity drainage. In one embodiment of this invention, multiple vertical propped planar inclusions are initiated from well casings and propagate into a hydrocarbon fluid bearing high energy reservoir formation. Further multiple vertical propped planar inclusions are initiated from other well casings and propagated into a shallower depleted hydrocarbon fluid bearing low energy reservoir formation. Carbon dioxide is injected and stored in both reservoir formations.

At off-peak energy periods, the carbon dioxide is pumped by a pump/turbine into the deeper high energy reservoir formation at a high energy state, and at peak energy periods the carbon dioxide is released from the high energy reservoir formation to the low energy reservoir formation through the pump/turbine to generate electricity to balance electrical loads on a power grid. The energy storage scheme is a closed cycle system with no atmospheric emissions.

The carbon dioxide is injected into the subsurface formation at supercritical conditions, and because of its miscibility with the oil and its gas like properties, the injection of carbon dioxide results in increased production of petroleum fluids by gravity drainage from the subsurface formation. Hydrocarbon fluids are produced from either one or both reservoir formations depending on the reservoir conditions, oil quality, and quantity of stranded oil reserves. Additional carbon dioxide is injected into the formations as hydrocarbon fluids are extracted.

In one embodiment, the pump/turbine is located on the surface. In another embodiment of the invention, the two reservoirs are located above and below each other, one being shallow and the other deep. The well casing intersects both reservoirs, and pump/turbine is located in the well casing below the surface and between high energy formation and the low energy formation.

Although the present invention contemplates the formation of vertical propped planar inclusions which generally extend laterally away from a vertical or near vertical well penetrating an earth formation and in a generally vertical plane, those skilled in the art will recognize that the invention may be carried out in earth formations wherein the fractures and the well bores can extend in directions other than vertical.

Other objects, features and advantages of the present invention will become apparent upon reviewing the following description of the preferred embodiments of the invention, when taken in conjunction with the drawings and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic isometric view of a carbon energy storage and oil recovery system having a first well casing with associated planar inclusions within a high energy formation and a second well casing with associated planar inclusions within a low energy formation in accordance with the present invention.

FIG. 2 is a section view of the well casings along section line 2-2 of FIG. 1 in accordance with the present invention.

FIG. 3 is a schematic isometric view of a carbon energy storage and oil recovery system having multiple well casings with associated planar inclusions within the high energy formation in accordance with the present invention.

FIG. 4 is a plot of the physical states of carbon dioxide for various temperatures and pressures.

FIG. 5 is a plot of the density of carbon dioxide for various temperatures and pressures.

FIG. 6 is a schematic isometric view of a carbon energy storage and oil recovery system having a single well casing with associated planar inclusions within a high energy formation and with associated planar inclusions within a low energy formation in accordance with the present invention.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT

Several embodiments of the present invention are described below and illustrated in the accompanying drawings. The present invention is a method and apparatus for the storage of carbon dioxide in subsurface formations, for providing a closed cycle energy storage method for balancing electrical loads on a power grid by transferring carbon dioxide between subsurface hydrocarbon bearing reservoir formations, and for enabling more efficient and economical recovery of petroleum fluids from the subsurface formations by gravity drainage with less environmental impact. Multiple vertical propped planar inclusions at various azimuths are constructed from multiple well casings into oil bearing formations and are filled with a proppant that yields highly permeable planar inclusions that greatly assist gravity drainage as an effective recovery method of hydrocarbon fluids. The installation of the multiple vertical propped planar inclusions enables both the carbon dioxide injection and withdrawal to be very efficient. The propped planar inclusions also enable gravity drainage as an effective recovery method in reservoir formations of low vertical permeability, in which oil reserves would otherwise be left stranded and unexploited. Several embodiments of the present invention are described below and illustrated in the accompanying drawings.

As is well known, extensive oil reservoirs are found in formations comprising unconsolidated, weakly cemented sediments with moderate to low vertical permeability due to silt and/or clay content. Unfortunately, the methods currently used for extracting the oil from these formations have yielded low recovery factors. Gravity drainage in these formations is limited due to the formation's low vertical permeability. Oil is not very mobile in these formations. Therefore, oil recovery can be enhanced by forming highly permeable planar inclusions in the formations and by injecting carbon dioxide into the permeable planar inclusions. The injected carbon dioxide mixes with the oil reducing its viscosity and thus increases the mobility of the oil. The oil can then flow under gravity into the permeable planar inclusions and into the well casing for production up oil production tubing in the well casing at flow rates that are virtually independent of the formation vertical permeability. See Hocking et al., “Unimpaired Performance of Single-Well SAGD in Variable Geology,” Gas & Oil Expo & Conference North America, 2011. Oil recovery by effective gravity drainage can yield recovery factors greater than 80%, whereas without the propped verticals planar inclusions recovery by primary and secondary recovery could be less than 30%. At 30% recovery, gravity drainage is not an effective recovery method. Thus the combination of carbon storage and closed cycle energy storage with enhanced gravity drainage oil recovery provides a most cost effective, efficient, and environmentally proactive system.

As is well known, the performance of the gravity drainage process is mainly controlled by the competition between capillary and gravity forces. The Bond number, Bo, is a dimensionless number that quantifies the importance of gravitational forces compared to interfacial forces as given by Bo=KΔρg/σ, with K being the formation permeability, Δρ the difference in density of the oil and the carbon dioxide, g the gravitational acceleration constant and σ the interfacial tension. A high Bo means that gravitational force is dominating and interfacial does not influence the gravity induced oil flow. Therefore, maximizing Δρ and minimizing σ, by appropriate selection of the supercritical carbon dioxide injection pressure and temperature is important.

FIG. 1 represents a carbon energy storage and oil recovery system 9 and serves to illustrate the associated method in accordance with the principles of the present invention. Two reservoir formations, a high energy reservoir formation 24 and a low energy reservoir formation 14, with respective cap rocks 26 and 16, are hydrocarbon fluid bearing formations that are considered depleted or legacy fields. The high energy formation 24 and the low energy formation 14 may be moderately permeable. The vertical permeabilities, however, are too low for gravity drainage to be an effective recovery method. Therefore, considerable reserves of oil remain in the high energy formation 24 and possibly in the low energy formation 14. The formations 24 and 14 are shown at differing elevations in FIG. 1, however they could be at similar elevations, or the high energy formation 24 may be deeper or shallower than the low energy formation 14. Which formation is held at the high energy state depends on reservoir conditions, oil quality, stranded reserves, etc. In general, the high energy formation 24 will be substantially deeper than the low energy formation 14. The terms “hydrocarbon fluids” and “oil” are used herein to indicate relatively low viscosity and low density hydrocarbons that have a moderate miscible pressure when exposed to supercritical carbon dioxide. The cap rocks 26 and 16 are geological traps for the hydrocarbons fluids and have stored the hydrocarbon fluids over geological time under considerable pressure. These cap rocks 26 and 16 are also suitable for the long term storage and containment of carbon dioxide.

The carbon energy storage and oil recovery system 9 of FIG. 1 includes two interconnected well systems 20 and 10, one for the high energy formation 24 and one for the low energy formation 14, respectively. The well system 20 is positioned within the high energy formation 24 and is used to inject carbon dioxide into the high energy formation 24, to withdraw carbon dioxide from the high energy formation 24, to inject fracture fluid into the high energy formation 24, and to withdraw oil by means of an oil production pump 28 from the high energy formation 24 via a sump 23. The other well system 10 is positioned within the low energy formation 14 and is used to inject carbon dioxide into the low energy formation 14, to withdraw carbon dioxide from the low energy formation 14, to inject fracture fluid into the low energy formation 14, and to withdraw oil by means of an oil production pump 18 from the low energy formation 14 via sump 13.

The high energy well system 20 includes a well casing 21, an expansion device 22, an oil production tube 27, a carbon dioxide conduit 25, and multiple vertical high permeability propped planar inclusions 30 within the formation 24. As best seen in FIG. 2, the carbon dioxide conduit 25 is the annular space between the oil production tube 27 and the well casing 21. The high energy carbon dioxide conduit 25 is connected to a pump/turbine 34 by means of a high energy pump/turbine port 37. The low energy well system 10 includes a well casing 11, an expansion device 12, an oil production tube 17, a carbon dioxide conduit 15 (the annular space between the oil production tube 17 and the well casing 11), and multiple vertical high permeability propped planar inclusions 30 within the formation 14. The low energy carbon dioxide conduit 17 is connected to the pump/turbine 34 by means of a low energy pump/turbine port 39. A carbon dioxide source 7 pumps carbon dioxide into the high energy formation 24 and the low energy formation 14 via the high-energy carbon dioxide conduit 25 and the low energy carbon dioxide conduit 15 to occupy the space created by the removal of oil from the formations.

The propped planar inclusions 30 are formed by injecting a suitable fracture fluid with proppant 51 into the expansion devices 22 and 12. The multiple vertical high permeable propped planar inclusions 30 enhance the injection and withdrawal of hydrocarbon fluids and carbon dioxide into and from the formations 24 and 14. The well systems 20 and 10 in FIG. 1 enable the enhanced recovery of hydrocarbon fluids by gravity drainage for producing oil from the sumps 23 and 13, via oil production tubes 27 and 17 to the ground surface 5 from formations 24 and 14. As hydrocarbons are produced, additional carbon dioxide can be injected into the formations 24 and 14 through carbon dioxide conduits 25 and 15.

During off-peak energy requirement periods, the carbon dioxide in the low energy formation 14 is pumped into the high energy formation 24, by the pump/turbine 34 driven by electrical power 31. The electrical power 31 may be supplied by a variable speed generator thus providing a refinement in balancing electrical loads on a power grid. As a result of the operation of the pump/turbine 34, the carbon dioxide in the high energy formation 24 is in a supercritical state and at a pressure greater than the miscible pressure, thus greatly assisting gravity drainage of oil. Hydrocarbon fluids (oil) are pumped to the surface 5 from the high energy formation 24 by the high energy oil production pump 28 via oil production tube 27. During peak energy requirement periods, the carbon dioxide is released from high energy formation 24 and flows via carbon dioxide conduit 25 through the pump/turbine 34 to low energy formation 14 and drives the pump/turbine 34 to produced peak demand electrical power 31. The cycle for the energy storage system 9 described above is a closed system with no atmospheric emissions. The continuous operation of the energy storage system 9 enhances the recovery of hydrocarbon fluids from the formations 24 and 14, allowing for greater volumes of carbon dioxide to be stored in the formations 24 and 14 of energy storage system 9.

Turning to FIG. 3, the high energy state reservoir formation 24 is shown to illustrate and describe in detail multiple well systems 20. Multiple vertical wells have been drilled into the formation 24, and the well casings 21 have been cemented in the formation 24 and in the overlying cap rock 26. The term “casing” is used herein to indicate a protective lining for a wellbore. Any type of protective lining may be used, including those known to persons skilled in the art as liner, casing, tubing, etc. Casing may be segmented or continuous, jointed or unjointed, conductive or non-conductive made of any material (such as steel, aluminum, polymers, composite materials, etc.), and may be expanded or unexpanded, etc.

With continuing reference to FIG. 3, the high energy well casings 21 have expansion devices 22 and the sump sections 23. The carbon dioxide conduits 25 are interconnected via pump/turbines (not shown). The formation 24 may comprise unconsolidated and/or weakly cemented sediments for which conventional fracturing operations are not well suited. The expansion devices 22 operate to expand the well casings 21 radially outward and thereby dilate the formation 24 proximate the expansion devices 22, in order to initiate the formation of the generally vertical and planar inclusions 30 extending outwardly from the well casings 21 at various azimuths. Suitable expansion devices for use in the well system 20 are described in U.S. Pat. Nos. 6,216,783, 6,330,914, 6,443,227, 6,991,037, 7,404,441, 7,640,975, 7,640,982, 7,748,458, 7,814,978, 7,832,477, 7,866,395, 7,950,456 and 8,151,874. The entire disclosures of these prior patents are incorporated herein by this reference. Other expansion devices or modes of formation deformation may be used in the well systems 20 in keeping with the principles of the invention.

Once the expansion devices 22 have expanded the well casings 21 radially outward, the fracture fluid with a proppant 51 is forced from the well casings 21 into the dilated formation 24 to propagate the planar inclusions 30 into the formation 24. The planar inclusions 30 are not necessarily formed simultaneously. As shown in FIG. 3, the well systems 20 each include eight planar inclusions 30. The well systems 20 do not necessarily need to have eight inclusions at the same depth orientated at various azimuths, but could consist of one, two, three, four, five, six or even seven vertical planar inclusions at various azimuths at the same depth, with such choice of the number of inclusions constructed depending on the application, formation type, and/or economic benefit. Also there is only one inclusion at a particular azimuth, whereas there could be other upper inclusions on the same azimuth, and in fact there could be numerous of these upper inclusions at progressively shallower depths.

With continuing reference to FIG. 3, the lower planar inclusions 30 are constructed first, with each wing of the eight planar inclusions 30 injected independently of the others. The well systems 20 are shown with the planar inclusions 30 constructed at only a single depth, these well systems 20 are shown as only one example of the invention. Alternative forms of the invention could contain numerous upper inclusions constructed at progressively shallower depths, depending on the formation thickness, the distribution of hydrocarbon fluids within the formation 24, and/or economic benefit.

The injected fracture fluid carries the proppant 51 to the extremes of the planar inclusions 30. Upon propagation of the planar inclusions 30 to their required lateral and vertical extent, the thickness of the planar inclusions 30 may need to be increased by utilizing the process of tip screen out. The tip screen out process involves modifying the proppant loading and/or modifying the properties of the injected fracture fluid to achieve a proppant bridge at the inclusion tips. The injected fracture fluid is further injected after tip screen out, but rather than extending the inclusion laterally or vertically, the injected fracture fluid widens, i.e. thickens, and fills the inclusion 30 from the inclusion tips back to the well casings 21 within the well bore.

The behavioral characteristics of the viscous injected fracture fluid are preferably controlled to ensure the propagating viscous planar inclusions 30 maintain their azimuth directionality, such that the viscosity of the injected fracture fluid and its volumetric rate are controlled within certain limits depending on the formation 24, the specific gravity of the proppant 51, and the size distribution of the proppant 51. For example, the viscosity of the injected fracture fluid is preferably greater than approximately 100 centipoise. If, however, a foamed injected fracture fluid is used, a greater range of viscosity and injection rate may be permitted while still maintaining directional and geometric control over the planar inclusions 30. The viscosity and volumetric rate of the injected fracture fluid needs to be sufficient to transport the proppant 51 to the extremities of the planar inclusions 30. The size distribution of the proppant 51 needs to be matched with that of the formation 24, to ensure formation fines do not migrate into the propped planar inclusion 30 during hydrocarbon fluid production. Typical size distribution of the proppant 51 would range from #12 to #20 U.S. mesh for oil sand formations, with an ideal proppant 51 being sand or ceramic beads and could also contain a mixture of fibers. Resin coated sand or ceramic beads are capable of mechanically binding the proppant 51 together without loss of permeability of the propped planar inclusion 30.

With continuing reference to FIG. 3, the well systems 20, have carbon dioxide injected into the formation 24 through the carbon dioxide conduits 25, and the hydrocarbons are produced to the surface 5 by the high energy oil production pump 28 through the oil production tubes 27 placed inside of the well casings 21. The oil is mobilized by the miscible carbon dioxide, flows under gravity from the formation 24 through the planar inclusions 30 towards the well systems 20, enters the sumps 23, and is pumped to surface 5 via the production tubes 27 by means of the production pump 28 that may include a PCP (progressive cavity pump), ESP (electrical submersible pump), gas lift, or natural lift, depending on operating temperatures, pressures, and depth of the well systems 20. The level of hydrocarbon fluids (oil) in the well systems 20 will be maintained above the inlets (sump 23) to the production tubes 27 to ensure carbon dioxide is not produced from the formation 24 up the production tubes 27. The production of hydrocarbon fluids includes the production of methane from the high energy formation and the low energy formation from a first portion of the well casing 21 located at the highest elevation in the high energy formation 24 and from a second portion of the well casing 11 located at the highest elevation in the low energy formation 14.

The formation 24 could be comprised of relatively hard and brittle rock, but the well systems 20 and the method find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which it is typically very difficult to obtain directional or geometric control over inclusions as they are being formed.

The selected range of temperatures and pressures to operate the process with the well systems 20 will depend on reservoir depth, ambient conditions, the quality of the in place oil and the presence of nearby water bodies. The process is operated at a pressure and temperature range that is optimal for miscible conditions of the carbon dioxide, plus maximizing the density difference of the oil and supercritical carbon dioxide to provide an efficient energy storage scheme. The operating pressure of the process may be selected to closely match the ambient reservoir conditions to minimize water inflow into the process zone and the well bore by the injection of the supercritical carbon dioxide.

In FIG. 4, the physical states of the carbon dioxide are shown at various temperatures and pressures, as a gas 40, as a solid 41, as a liquid 42, and as a supercritical fluid 43. The critical point 44 is at a temperature of 304.25° K and at a pressure of 72.9 bar.

In FIG. 5, the density of the carbon dioxide is shown at various temperatures and pressures. The critical point 44 is shown in FIG. 4. At a temperature 45 of 310° K, the density of the carbon dioxide changes significantly with pressure, while at a higher temperature 46 of 330° K, the change is less. While at a still at higher temperature 47 of 400° K, the density change with pressure is much more like a gas. It is therefore imperative to site the system 9 at pressure and temperature conditions in formations 24 and 14 that yield the most optimal energy storage scheme and the viable enhanced recovery of hydrocarbon fluids. Thus the system 9 is better suited for formations that are in areas of high geothermal heat flow to achieve an optimal system 9.

In FIG. 6, a variation of the carbon energy storage and oil recovery system 9 is shown, wherein the high energy formation 24 is located below the low energy formation 14. In this case, the high energy well system 20 and at the low energy well system 10 can be constructed with a single well casing 11 that penetrates both formations 24 and 14. In this system 9, the pump/turbine 34 is located in the subsurface between the high energy well system 20 and the low energy well system 10 and is connected to the carbon dioxide conduit 15. Such an arrangement can achieve a more optimum efficient system 9 compared to the surface located pump/turbine 34 shown in the system 9 in FIG. 1.

However, the present disclosure provides information to enable those skilled in the art of oil recovery, energy storage, hydraulic fracturing, and soil and rock mechanics to practice the method enabled by system 9 and for well systems 20 and 10 to initiate and control the propagation of a viscous injected fracture fluid in weakly cemented sediments, and importantly for the propagating planar inclusions 30 to intersect and coalesce with earlier placed permeable planar inclusions 30 and thus form a continuous planar inclusion 30 on a particular azimuth from within a single well system 20 or 10 or between multiple well systems.

The system 9 and associated method are applicable to formations 24 and 14 of weakly cemented sediments with low cohesive strength compared to the vertical overburden stress prevailing at the depth of interest. Low cohesive strength is defined herein as no greater than 3 MegaPasca (MPa) plus 0.4 times the mean effective stress (p′) in MPa at the depth of propagation.

c<3 MPa+0.4p′  (1)

where c is cohesive strength in MPa and p′ is mean effective stress in the formation.

Examples of such weakly cemented sediments are sand and sandstone formations, mudstones, shales, and siltstones, all of which have inherent low cohesive strength. Critical state soil mechanics assists in defining when a material is behaving as a cohesive material capable of brittle fracture or when it behaves predominantly as a ductile frictional material.

Weakly cemented sediments are also characterized as having a soft skeleton structure at low effective mean stress due to the lack of cohesive bonding between the grains. On the other hand, hard strong stiff rocks will not substantially decrease in volume under an increment of load due to an increase in mean stress.

In the art of poroelasticity, the Skempton B parameter is a measure of a sediment's characteristic stiffness compared to the fluid contained within the sediment's pores. The Skempton B parameter is a measure of the rise in pore pressure in the material for an incremental rise in mean stress under undrained conditions.

In stiff rocks, the rock skeleton takes on the increment of mean stress and thus the pore pressure does not rise, i.e., corresponding to a Skempton B parameter value of at or about 0. But in a soft soil, the soil skeleton deforms easily under the increment of mean stress and, thus, the increment of mean stress is supported by the pore fluid under undrained conditions (corresponding to a Skempton B parameter of at or about 1).

The following equations illustrate the relationships between these parameters in equations denoted as (2) as follows:

Δu=BΔp

B=(K _(u) −K)/(αK _(u))

α=1−(K|K _(s))  (2)

where Δu is the increment of pore pressure, B the Skempton B parameter, Δp the increment of mean stress, K_(u) is the undrained formation bulk modulus, K the drained formation bulk modulus, α is the Biot-Willis poroelastic parameter, and K_(s) is the bulk modulus of the formation grains. In the system 9 and associated method, the bulk modulus K of the formation for inclusion propagation is preferably less than approximately 5 GPa.

For use of the system 9 and method in weakly cemented sediments, preferably the Skempton B parameter is as follows with p′ in MPa:

B>0.95exp(−0.04p′)+0.008p′  (3)

The system 9 and associated method are applicable to the formations 24 and 14 of weakly cemented sediments (such as tight gas sands, mudstones and shales) where large extensive propped vertical permeable drainage planar inclusions 30 are desired to intersect thin sand lenses and provide drainage paths for greater gas production from the formations. In weakly cemented formations containing heavy oil (viscosity>100 centipoise) or bitumen (extremely high viscosity>100,000 centipoise), generally known as oil sands, propped vertical permeable drainage planar inclusions 30 provide drainage paths for cold production from these formations, and access for steam, solvents, oils, and heat to increase the mobility of the petroleum hydrocarbons (oil) and thus aid in the extraction of the hydrocarbon fluids from the formation. In highly permeable weak sand formations, permeable drainage planar inclusions 30 of large lateral length result in lower drawdown of the pressure in the reservoir, such as formation 24, which reduces the fluid gradients acting towards the well casing 21, resulting in less drag on fines in the formation 24, and resulting in reduced flow of formation fines into the well casing 21.

The 51 proppant is carried by the injected fracture fluid resulting in a highly permeable planar inclusion 30. Such proppants 51 are typically clean sand or specialized manufactured particles (generally ceramic in composition), and depending on the size composition, closure stress and proppant type, the permeability of the fracture can be controlled. Either type of proppant 51 could be resin coating to provide for bounding between proppant particles. The proppant 51 could contain fibers, composed of carbon, polyethylene and/or rubber of diameter similar to the sand proppant but with lengths greater than 10× the sand proppant diameter. The permeability of the propped planar inclusions 30 will typically be orders of magnitude greater than the formation 24 permeability, generally at least by two orders of magnitude.

The injected fracture fluid varies depending on the application and can be water, oil, or multi-phased based gels. Aqueous based injected fracture fluids consist of a polymeric gelling agent such as solvatable (or hydratable) polysaccharide, e.g. galactomannan gums, glycomannan gums, and cellulose derivatives. The purpose of the hydratable polysaccharides is to thicken the aqueous solution and thus act as viscosifiers, i.e. increase the viscosity by 100 times or more over the base aqueous solution of the injected fracture fluid. A cross-linking agent can be added which further increases the viscosity of the solution of the injected fracture fluid. The borate ion has been used extensively as a cross-linking agent for hydrated guar gums and other galactomannans (see U.S. Pat. No. 3,059,909 to Wise). Other suitable cross-linking agents are chromium, iron, aluminum, zirconium (see U.S. Pat. No. 3,301,723 to Chrisp), and titanium (see U.S. Pat. No. 3,888,312 to Tiner et al). A breaker is added to the solution of the injected fracture fluid and to controllably degrade the viscous fracturing injected fracture fluid. Common breakers are enzymes and catalyzed oxidizer breaker systems, with weak organic acids sometimes used.

Finally, it will be understood that the preferred embodiment has been disclosed by way of example, and that other modifications may occur to those skilled in the art without departing from the scope and spirit of the appended claims. 

What is claimed is:
 1. A carbon energy storage and oil recovery method comprising the steps of: a. propagating an inclusion filled with a proppant into a high energy formation from a well casing extending from a ground surface into the high energy formation; b. propagating an inclusion filled with a proppant into a low energy formation from the well casing extending from the ground surface into the low energy formation; c. injecting carbon dioxide into the high energy formation and the low energy formation through a carbon dioxide conduit disposed in the well casing; d. during off-peak energy demand times, pressurizing the carbon dioxide in the high energy formation by pumping carbon dioxide from the low energy formation through the carbon dioxide conduit into the high energy formation by means of a pump/turbine; e. during peak energy demand times, releasing the carbon dioxide from high energy formation to the low energy formation through the carbon dioxide conduit and through the pump/turbine to generate electricity; and f. producing hydrocarbon fluids in the high energy formation or the low energy formation up an oil production tube in the well casing.
 2. The method of claim 1, wherein the well casing comprises a high energy well casing extending from the ground surface into the high-energy formation and a low energy well casing extending from the ground surface into the low energy formation.
 3. The method of claim 1, wherein the method further includes a plurality of inclusions at varying azimuths in the high energy formation and the low energy formation.
 4. The method of claim 3, wherein the plurality of inclusions are initiated from the well casing by injecting an injection fluid, including the proppant, from the well casing into the high energy formation and into the low energy formation, wherein the inclusions are positioned at progressively shallower depths after the viscosity of the injection fluid in the immediate lower inclusions has reduced so that the plurality of inclusions at the shallower depths intersect and coalesce with the inclusions immediately beneath on their respective azimuths.
 5. The method of claim 4, wherein the method further includes providing a plurality of well casings with associated inclusions at varying azimuth in the high energy formation and in the low energy formation.
 6. The method of claim 1, wherein the proppant has particles of size ranging from #4 to #100 U.S. mesh and is selected from the group including sand, ceramic beads, resin coated sand, resin coated ceramic beads, fibers, or a mixture thereof.
 7. The method of claim 1, wherein the carbon dioxide is injected into the high energy formation and the low energy formation at a supercritical state and above the miscible pressure of hydrocarbon fluids in the high energy formation and the low energy formation.
 8. The method of claim 1, wherein the carbon dioxide injection is a continuous injection, and the production of hydrocarbon fluids is continuous.
 9. The method of claim 1, wherein the carbon dioxide injection is a pressure pulsed cyclic injection or intermittent injection.
 10. The method of claim 1, wherein the high energy formation and the low energy formation form a closed carbon energy storage system for cyclic energy states of the carbon dioxide between the high energy formation and the low energy formation.
 11. The method of claim 10, wherein cyclic energy states of the carbon dioxide are cycled by the pump/turbine.
 12. The method of claim 11, wherein the pump/turbine is driven by a variable speed generator.
 13. The method of claim 11, wherein the pump/turbine is located above the ground surface.
 14. The method of claim 11, wherein the pump/turbine is located below the ground surface.
 15. The method of claim 1, wherein the injection of the carbon dioxide into the low energy formation is at an injection pressure and temperature so that the carbon dioxide is in its supercritical state and above the miscible pressure of the hydrocarbon fluids.
 16. The method of claim 1, wherein the injection of the carbon dioxide injection into the low energy formation is at an injection pressure and temperature that provide a maximum density difference between the hydrocarbon fluids and the carbon dioxide to thereby achieve efficient enhanced recovery of the hydrocarbon fluids by gravity drainage.
 17. The method of claim 1, wherein the high energy formation has a Skempton B parameter greater than 0.95 exp(−0.04p′)+0.008p′, where p′ is the mean effective stress in MPa at the depth of the propagating inclusion.
 18. The method of claim 1, wherein the low energy formation has a Skempton B parameter greater than 0.95 exp(−0.04p′)+0.008p′, where p′ is the mean effective stress in MPa at the depth of the propagating inclusion.
 19. The method of claim 1, wherein methane is produced from the high energy formation and the low energy formation from a first portion of the well casing located at the highest elevation in the high energy formation and from a second portion of the well casing located at the highest elevation in the low energy formation.
 20. A carbon energy storage and oil recovery system for recovery hydrocarbon fluids from a formation having a high energy formation and a low energy formation, the system comprising: a. high energy well system located in the high energy formation comprising: i) a well casing extending from a ground surface into the high energy formation; ii) a high energy expansion device in the well casing for propagating an inclusion filled with a proppant into the high energy formation from the well casing; iii) a high energy carbon dioxide conduit with a first end and a second end wherein the first end communicates with the inclusions in the high energy formation; and iv) an oil production tube with a first end communicating with the formation and a second end extending to the ground surface for delivery of hydrocarbons from the formation to the ground surface for recovery; b. low energy well system located in a low energy formation comprising: i) the well casing further extending into the low energy formation; ii) a low energy expansion device in the well casing for propagating an inclusion filled with a proppant into the low energy formation from the well casing; iii) a low energy carbon dioxide conduit with a first end and a second end wherein the first end communicates with the inclusions in the low energy formation; and c. a carbon dioxide source for injecting the carbon dioxide into the high energy formation and the low energy formation by means of the high energy carbon dioxide conduit and the low energy carbon dioxide conduit; d. a pump/turbine connected between the second end of the high energy carbon dioxide conduit and the second end of the low energy carbon dioxide conduit for pressurizing the carbon dioxide in the high energy formation by pumping carbon dioxide from the low energy formation during off-peak energy demand times and for generating electricity by the release of the carbon dioxide from the high energy formation to the low energy formation during peak energy demand times; and e. a hydrocarbon production pump for pumping hydrocarbons in the formation up the oil production tube.
 21. The system of claim 20, wherein the well casing comprises a high energy well casing extending from the ground surface into the high-energy formation and a low energy well casing extending from the ground surface into the low energy formation.
 22. The system of claim 20, wherein the system further includes a plurality of inclusions at varying azimuths in the high energy formation and the low energy formation.
 23. The system of claim 22, wherein the plurality of inclusions are initiated from the high energy expansion device of the well casing by injecting an injection fluid, including a proppant, from the well casing into the high energy formation and are initiated from the low energy expansion device of the well casing by injecting the injection fluid, including the proppant, from the well casing into the low energy formation, wherein the inclusions are positioned at progressively shallower depths after the viscosity of the injection fluid in the immediate lower inclusions has reduced so that the plurality of inclusions at the shallower depths intersect and coalesce with the inclusions immediately beneath on their respective azimuths.
 24. The system of claim 23, wherein the system further includes providing a plurality of well casings with associated inclusions at varying azimuth in the high energy formation and in the low energy formation.
 25. The system of claim 20, wherein the proppant has particles of size ranging from #4 to #100 U.S. mesh and is selected from the group including sand, ceramic beads, resin coated sand, resin coated ceramic beads, fibers, or a mixture thereof.
 26. The system of claim 20, wherein the carbon dioxide source injects the carbon dioxide through the high energy carbon dioxide conduit into the high energy formation and through the low energy carbon dioxide conduit into the low energy formation at a supercritical state and above the miscible pressure of hydrocarbon fluids in the high energy formation and the low energy formation.
 27. The system of claim 20, wherein the carbon dioxide source injects the carbon dioxide in a continuous injection, and the production of hydrocarbon fluids is continuous.
 28. The system of claim 20, wherein carbon dioxide source injects the carbon dioxide in a pressure pulsed cyclic injection or intermittent injection.
 29. The system of claim 20, wherein the high energy carbon dioxide conduit and the low energy carbon dioxide conduit form a closed carbon energy storage system with the pump/turbine for cyclic energy states of the carbon dioxide between the high energy formation and the low energy formation.
 30. The system of claim 29, wherein cyclic energy states of the carbon dioxide are cycled by the pump/turbine system.
 31. The system of claim 30, wherein the pump/turbine is driven by a variable speed generator.
 32. The system of claim 30, wherein the pump/turbine is located above the ground surface.
 33. The system of claim 30, wherein the pump/turbine is located below the ground surface.
 34. The system of claim 20, wherein carbon dioxide source injects the carbon dioxide into the low energy formation at an injection pressure and temperature so that the carbon dioxide is in its supercritical state and above the miscible pressure of the hydrocarbon fluids.
 35. The system of claim 20, wherein the carbon dioxide source injects the carbon dioxide into the low energy formation at an injection pressure and temperature that provide a maximum density difference between the hydrocarbons and the carbon dioxide to thereby achieve efficient enhanced recovery of the hydrocarbon fluids by gravity drainage.
 36. The system of claim 20, wherein the high energy formation has a Skempton B parameter greater than 0.95 exp(−0.04p′)+0.008p′, where p′ is the mean effective stress in MPa at the depth of the propagating inclusion.
 37. The system of claim 20, wherein the low energy formation has a Skempton B parameter greater than 0.95 exp(−0.04p′)+0.008p′, where p′ is the mean effective stress in MPa at the depth of the propagating inclusion.
 38. The system of claim 20, wherein methane is produced from the high energy formation and the low energy formation from a first portion of the well casing located at the highest elevation in the high energy formation and from a second portion of the well casing located at the highest elevation in the low energy formation. 